Coiled tubing is often used to deploy downhole equipment. Coiled tubing (CT) can be defined as any continuously-milled tubular product manufactured in lengths that require spooling onto a take-up reel. Although initially used primarily for well cleanout and acid stimulation applications, coiled tubing is now used in other applications, including well unloading, fishing, tool conveyance and setting/retrieving plugs. The term “downhole assembly” refers generally to the equipment that is deployed and used in a subterranean well. Electrical submersible pumps, fishing tools and monitoring devices are common examples of downhole equipment.
Coiled tubing units typically include an injector head that is suspended above the wellhead by a crane or derrick. The injector head provides the surface drive force to run and retrieve the coiled tubing from the well. The injector head is often used in conjunction with a stripper and a blowout preventer (BOP). The stripper is typically located between the injector head and the BOP and provides the primary operational seal between pressurized wellbore fluids and the surface environment. The BOP may include one or more rams that perform various functions, including supporting the hanging coiled tubing, sealing around the coiled tubing and shearing the coiled tubing.
One of the drawbacks of using coiled tubing in conjunction with downhole equipment is the process used to connect the downhole equipment to the coiled tubing before lowering the downhole equipment into the well. In the past, a conventional lubricator was used to load tools before running the tools into the live well. The lubricator is a long, high-pressure pipe that is fitted between the top of a wellhead and the bottom of the injector head. The tools are assembled inside the lubricator and connected to the coiled tubing. The lubricator is then pressurized to wellbore pressure and the assembled tools are deployed through the wellhead into the well.
While generally effective, the prior art method of “lubricating” tools into the well suffers significant drawbacks. Most significantly, the use of a lubricator raises the injector head high above the wellbore for the duration of the coiled tubing operation. This requires the use of large cranes or derricks that decrease the cost effectiveness and efficiency of the coiled tubing deployment. Many well sites are too remote or two small to support the use of large cranes or derricks. Furthermore, elevated injector heads are unstable in high winds and pose an increased risk to operators and equipment.
In light of the shortcomings of the existing art, there is a need for an improved apparatus and method for lubricating a downhole assembly into a live well. It is to these and other deficiencies in the prior art that the present invention is directed.